Compartmentalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in the crude oil in agreement with recent laboratory results, and settle preferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features, in this case the asphaltene concentration gradient, are then integrated in a geologic model and used to predict crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data matched for the first production well, establishing that the penetrated sands are likely connected, mitigating compartmentalization risk. This DFA log prediction protocol offers a new method to optimize wireline logging.
Knowledge of reservoir architecture is critical to successful development planning.1 Indeed, history matching of production data is extremely useful for understanding the reservoir.2 However, in high-cost arenas where expensive production facilities must be in place prior to production of first oil, history matching for facilities design is precluded. The connectivity of the producing units throughout the field is a major uncertainty and risk factor that behooves conventional as well as novel analytic approaches. Reservoir compartmentalization (the inverse of connectivity) impacts all production strategies, and therefore mandates the use of all sources of information that may help unravel reservoir complexities. One key and relatively new technology that is increasingly exploited for reservoir characterization is Downhole Fluid Analysis (DFA). DFA enables characterization of the fluid in the oil column, creating in essence a continuous downhole fluid log. With a multi-well approach DFA can address the fluid distribution throughout the reservoir. Because reservoir fluids are typically compositionally graded,3 different compartments are often filled with different fluids. Thus DFA can identify compartments.4
Acquisition of representative reservoir fluid samples is essential at the early stages of exploration. Ideally, fluids would be analyzed in their existing conditions, i.e. in the formation; however a detailed analysis of the fluid in the rock is not possible today. The closest alternative is the acquisition of downhole fluid samples accompanied by a real time fluid analysis (DFA) while sampling. One of the methods available for downhole fluid sampling is via a wireline formation testing and sampling tool (WFT). With current technology it is possible to obtain contamination-free samples in a very short time.5 Furthermore, this technique enables the acquisition of samples at different depths with unmatchable vertical resolution. Proper sampling practices are essential to preserve the composition of the extracted fluid as close as possible to that in the formation, minimizing as much as possible the risk of undesirable phase transitions.
Wireline-conveyed formation testing and sampling tools are described in detail elsewhere.6 Figure 1 is a schematic representation of one possible configuration of WFT tool with two DFA modules, a pumpout model, sample modules containing the sampling bottles and two single-probe modules. On the right side of this figure is a picture of the sampling probe. The probe is set in the wellbore against the reservoir rock and fluids are extracted from the formation into the tool flowline by creating a controlled differential pressure with a pump. The contents of the flowline are analyzed in any of the DFA modules, which are based primarily on Visible-Near-Infrared (Vis-NIR) absorption spectroscopy. The lightabsorption characteristics of crude oils differ from those of gas, water and oil-based mud filtrate, enabling a quantitative analysis of the fluids flowing through the downhole fluid analyzer.